Technical Support Document (TSD) for the CAA Section 111(d) Emission Guidelines for Existing Power 

Plants

Docket ID No. EPA-HQ-OAR-2013-0602

Goal Computation Technical Support 

Document

U.S Environmental Protection Agency

Office of Air and Radiation

June 2014
2

State Emission Rate Goal Setting under 111(d)

This Technical Support Document (TSD) provides information that supports the EPA’s determination of

state emission rate goals under the Proposed Rule. Section VII of the preamble discusses state emission

rate goals more broadly, and the Green House Gas (GHG) Abatement Measures TSD explains the 

technical basis for the development of the Best System of Emission Reductions (BSER) that inform the 

state goals. This TSD provides detailed explanation of the data, the data underlying the state goal 

calculation, the BSER-based calculations used to determine the state goals, and the state goals. The TSD 

is organized as follows:

1. BSER Factors Informing State Emission Rate Goals

a. Heat rate improvement 

b. Coal-to-gas redispatch 

c. Renewable (RE) and nuclear generation

d. End-use energy efficiency

2. Data Used

a. Rationale for historic data basis for state goal setting

b. Source of data

i. Emissions & Generation Integrated Resource Database (eGRID)

ii. Data sources for “under construction” units coming online post 2012

c. State-level data rationale and significance

3. Example of State Goal Calculation and Discussion

4. Appendix (attached Excel Workbook)

 Appendix 1 - State-level goals, underlying state-level data, and calculations for Proposed 

state goals

 Appendix 2 - State-level goals, underlying state-level data, and calculations for the 

Alternative state goals

 Appendix 3 - Summary table of state goals

 Appendix 4 - Block 1 & 2 only goals

 Appendix 5 - 2012 emission rates and building block application

 Appendix 6 - Description of state-level data development

 Appendix 7 - 2012 plant-level data and unit-level inventory

Note – This TSD also contains an excel attachment that contains the aggregate state-level data, 

calculations, and proposed state emission rate goals. The underlying plant-level data and unit-level data

is also available in the Docket for this rulemaking.
3

In EPA’s technical evaluation, reasonable assumptions regarding application of each GHG reducing 

technology were identified (see GHG Abatement Measures TSD). The EPA used these assumptions to 

develop the two regulatory options provided in this proposal: (1) Proposed state goals based on 

reasonable assumptions related to BSER, and (2) Alternative state goals with less ambitious assumptions

relative to those used for the Proposed state goals.

1. BSER Factors Informing State Emission Rate Goals

The GHG Abatement Measures TSD describes the four categories of emission reduction 

measures (building blocks) used in determining the state emission rate goals. That document 

describes EPA’s historic data review and analysis underlying each technology and informing 

EPA’s assessment of its feasibility and cost-effectiveness as part of a BSER. The technology 

estimates determined through EPA’s analysis and documented in the GHG Abatement Measures 

TSD are summarized below. These estimates are used in EPA’s calculation of state emission rate 

goals, as described in this TSD. 

a. Heat Rate Improvement

Proposed – A 6% heat rate improvement in the state’s coal fleet

Alternative – A 4% heat rate improvement in the state’s coal fleet

b. Redispatch to Existing Natural Gas Combined Cycle Plants (NGCC)

Proposed – a 70% capacity factor (CF) ceiling for the state’s NGCC fleet

Alternative – a 65% capacity factor ceiling for the state’s NGCC fleet

Note – These capacity factor values represent ceilings for NGCC utilization. The EPA 

used these ceilings while calculating state goal adjustments related to redispatching coal 

and/or oil and gas (O/G) steam generation to the state’s NGCC capacity.

c. Renewable and Nuclear 

Both Proposed and Alternative state goals include under construction (5.5 GW) and at 

risk nuclear capacity (~5.8% of nuclear capacity)

Proposed –RE at 13% by start of 2030 and thereafter*

Alternative –RE at 9.4% by start of 2025 and thereafter*

d. End-use Energy Efficiency (EE)*

Proposed – 10.7% cumulative savings by start of 2030 and each year thereafter

Alternative – 5.2% cumulative savings by start of 2025 and thereafter

*Note – The above RE values and EE saving rates are nationwide averages. Each state’s 

CO2 emission rate goal is informed by state-specific RE and EE values that relate to its 

pre-existing RE generation and EE savings rates respectively as described in the GHG 

Abatement Measures TSD. Also, the RE estimates do not count existing hydro 

generation.
4

The technology assumptions described above are used to determine an emission rate (lb/MWh) 

for each state that constitutes the state goal. As these building blocks reflect both fossil and nonfossil measures, the corresponding state goal reflects a composite emission rate including fossil 

and zero emitting non-fossil technologies. The EPA proposed to use an emission-rate metric for 

state goals, rather than a mass-based metric to promote state flexibility. See preamble section VII

for more description on the rate based standard.

2. Data Used

A. Rationale for Historic Data Basis for State Goal Setting

The EPA used 2012 state-level data to determine each state’s emission rate goal. The EPA 

carefully considered using a historic year data set, a projected year data set, or a hybrid of the two 

as a starting point for applying the above technology assumptions and calculating the state’s 

emission rate goals.

1

 Ultimately the EPA chose the historic data approach as it reflected actual 

historic performance at the state level. EPA chose the year 2012 as it represented the most recent 

year for which complete data were available at the time of the analysis. The EPA also considered

the possibility of using average fossil generation and emission rate values over a baseline period 

(e.g., 2009 – 2012), but determined that there would be little variation in results compared to a 

2012 base year data set due to the rate-based nature of the goal. The state goal is an emission rate 

representing the deployment of BSER measures, and that deployment level is largely a function 

of technology-specific emission rate reduction capability and total NGCC capacity installed to 

date. Because these two critical variables do not vary significantly when looking at a larger 

baseline period, the benefits of an expanded baseline period are dampened, and overshadowed by 

the complexities introduced through creating a “hypothetical” year. Consequently, the EPA 

decided that using data from an actual year (for which facility representatives had reported the 

values as complete and accurate to the best of their knowledge) was preferable to using calculated 

values that did not reflect any real year supply/demand balance. 

For this work, the EPA used 2012 data compiled using the same methodology as in EPA’s 

Emissions and Generation Resource Integrated Database (eGRID) to determine the following 

2012 values at the state level, which become the basis from which state emission rate goals are 

calculated.

 State level coal generation

 State level coal emission rate 

 State level oil/gas steam generation

 State level oil/gas steam emission rate

 State level NGCC generation

 State level NGCC emission rate

 State level NGCC capacity

 “Other” generation

 

1 Data sources for future year or hybrid approach would be EPA Base Case Power Sector modeling.
5

 “Other” emissions2

All generation values are expressed as net generation. Emission rate values are net emission rates 

and expressed as lbs/MWh. The capacity expressed is nameplate capacity in Megawatts.

B. Source of Data

i. Emissions & Generation Integrated Resource Database (eGRID) 

eGRID is a comprehensive inventory of environmental attributes of the U.S. electric power 

system. It is the preeminent source of air emissions data for the electric power sector, based on 

available plant-specific data for all U.S. electricity generating plants that provide power to the 

electric grid and report data to the U.S. government. eGRID integrates many different data 

sources on power plants and power companies, including, but not limited to: the EPA, the Energy 

Information Administration (EIA), the North American Electric Reliability Corporation (NERC), 

and the Federal Energy Regulatory Commission (FERC). Emissions data from the EPA are 

carefully integrated with generation data from EIA to produce useful values like pounds per 

megawatt-hour (lb/MWh) of emissions, which allows direct comparison of the environmental 

attributes of electricity generation. Although 2012 eGRID data had not yet been released, the 

EPA applied its eGRID methodology for matching the publically available and reported 2012 

emissions and generation data. The EPA relies on this most recent data to calculate state goals.

The state level totals for each technology category described in the above bullets are intended to 

reflect the electric generating units (EGUs) meeting the following criteria:3

In general, a covered EGU is a stationary combustion turbine, steam generating unit or IGCC that 

is: (1) capable of combusting more than 250 MMBtu/h heat input of fossil fuel and (2) 

constructed for the purpose of supplying one-third or more of its potential net- electric output 

capacity and more than 219,000 MWh to any utility power distribution system for sale (that is, 

to the grid). In addition, for a stationary combustion turbine to be considered an EGU the heat 

input must consist of over 90% natural gas.

4

Integrated gasification combined cycles (IGCCs) and combustion turbines (CTs) operating at a 

capacity factor greater than 33% are not part of the inventory of units subjected to building blocks 

one and two. Although they are covered units under the rule, they are excluded from the 

 

2

“Other” includes fossil sources that are likely subject to 111(d) rulemaking, but not subject to building block 

abatement measures (e.g., IGCC, high utilization CTs, useful thermal output at cogeneration units).

3 The set of sources used to compile state-level totals and eventual state goal rates does not constitute an 

applicability determination for any particular EGU. The ultimate universe of EGUs subject to this rulemaking may 

vary from that used in this goal setting exercise and will be determined by the rule’s applicability language and 

actual operating conditions at that plant.

4 See Preamble and Regulatory text for full description of 111(d) applicability criteria
6

generating technologies that are considered eligible for blocks one and two, and instead 

designated as the “other” category. IGCCs and high utilization CTs present unique circumstances

and are not subjected to building block application. IGCCs represent a very small sample size of 

three operating plants and have a different utilization pattern and different capital cost profile than 

NGCCs that result in a different set of redispatch economics. Likewise, high utilization CTs that 

may be covered by the rule are generally less efficient and have higher emission rates than 

NGCCs, and are therefore generally less cost effective for redispatch purposes.5 Therefore, 

IGCCs and CTs were not considered for cost-effective deployment of BSER building blocks one 

and two (i.e., there are no redispatch or heat rate improvements assumed to occur at these units). 

The historical generation and emissions from IGCCs and high capacity factor CTs are still 

averaged into the state goal to account for these units as affected sources. Therefore, their

generation and emissions would be averaged into the state emission rate for compliance purposes. 

This category of affected units that are covered under the 111(d) applicability language, but not 

subjected to BSER technologies, is accounted for in an “other” category. The IGCC and high 

utilization CTs represent a small portion (i.e., less than 1%) of total generation and emissions 

relative to the other affected source categories, and has a small impact on the state goal rates.

Appendix 1 shows the 2012 state-level aggregate data and corresponding calculations applied to 

achieve the state goal rate. 

ii. Data sources for under construction units

Although the 2012 eGRID data described above forms the starting point for the goal calculation, 

the EPA’s BSER methodology also included under construction nuclear and NGCC capacity that 

was not operating in 2012. For this small subset of “existing” units, EPA relied on its National 

Electric Energy Data System (NEEDS). NEEDS includes basic geographic, operating, capacity, 

and other data on existing or under construction generating units. NEEDS was completely 

updated for EPA's new power sector modeling platform v.5.13. For a description of the sources 

used in preparing NEEDS v.5.13, see Documentation, Chapter 4: Generating Resources.

6

 In 

addition to those under construction NGCC units in NEEDS, the EPA identified three other 

NGCC plants and one IGCC plant that were under construction and would likely fit the 

rulemaking’s definition of “existing” unit. These were the Dominion Brunswick plant in Virginia 

(1,358 MW), the Cheyenne Generating Station in Wyoming (220 MW), the Cane Run plant in 

Kentucky (640 MW), and the Kemper IGCC plant in Mississippi (582 MW).

C. State-Level Data Rationale and Significance

 

5

“High utilization” CTs are categorized as those with a capacity factor greater than 33% in 2012.

6 http://www.epa.gov/powersectormodeling/BaseCasev513.html#needs, also available in the Docket File titled 

“NEEDSv.5.13 Database”
7

The EPA aggregated plant-level data to the state level for purposes of state-specific emission rate 

goal calculation. Then, for each state, the EPA made BSER-related adjustments to the historical

state-level data to derive a new emission rate that constitutes the state goal. In making 

adjustments to aggregate state-level data, the EPA is simply suggesting that BSER assumptions 

(e.g., 6% heat rate improvement for the coal fleet) can be achieved on average at the state level. 

The EPA is not making any assertions about specific units or plants. The EPA recognizes the 

uniqueness and complexity of individual power plants, and is aware that there are site-specific 

factors that may prevent some EGUs from achieving performance equal to state-level 

assumptions. Likewise, the EPA also recognizes that some EGUs are capable of, and regularly 

do, achieve performance levels that surpass the BSER values assumed. In any case, the EPA is 

not making those unit-level evaluations in this exercise. The EPA is instead attempting to 

quantify what is feasible at the state level based on application of the BSER values to historic 

state-level data. Therefore, the ability or inability of a specific EGU to under/overachieve the 

assumed technology value cannot be taken, on its own, as an indication of the appropriateness of 

the state goals estimated using this approach.
8

3. Example of State Goal Calculation and Discussion

EPA’s methodology for calculating state goals is described in the steps below. The implementation of each step is illustrated in the table below its 

description, using the state of Ohio as an example. The mathematical calculations are fundamental to translating the building blocks into a 

quantifiable state goal.

Step 1: Calculation of unadjusted 2012 state fossil emission rate for covered sources

As noted above, the EPA begins the state goal emission rate calculation by starting with actual historic data at the state level. Plant-level data are

summed to state-level values describing: coal generation, coal emission rate, NGCC generation, NGCC emission rate, OG steam generation, OG

steam emission rate, “other” emissions, “other” generation, and NGCC capacity. These categories are identified as they represent the historical 

generation that is subject to building block application and/or would likely be subject to the state goal. For combined heat and power (CHP) units 

that are covered under the rule, the emissions and energy output associated with the useful thermal output not used for electricity production are 

included in the state goal and would be reported under the 111(d) reporting guidelines if the unit meets the 111(d) applicability criteria. The 

emissions and energy output associated with the useful thermal output are captured in the “other” category. The emission rates shown reflect total 

emissions divided by total net energy output (e.g. net electricity generation + useful thermal output).

7

 However, only the electricity generation 

portion of CHP is available for redispatch purposes, and therefore only this portion of the cogeneration operation is reflected in the technology 

generation totals.8 There are four coal facilities that co-fired biomass in 2012 that did not report emissions under Part 75 in these cases an emission 

rate factor is used to estimate stack CO2 emissions attributable to the type of biomass reported.

9,10

 These technology specific values become the 

basis for calculating the state’s emission rate. All emission rates provided in the state goal determination are on a net basis. 

 

7 A separate state goal rate is calculated for the EPA Integrated Planning Model (IPM) power sector analysis that reflects total emissions from CHP units, but just 

their net electricity generation in the denominator. This was necessary as IPM is a dispatch model that optimizes around net electricity demand, so it reflects 

total emissions associated with cogeneration operation, but only the generation associated with meeting net electricity demand. These corresponding goals 

expressed in lb/net MWh of electricity generation can be found in the docket file titled “State Goals (excluding useful thermal output)”.

8 The useful thermal output is converted to a net MWh value and captured in the other generation

9 40 CFR, Part 98, Subpart C, Table C-1A has CO2 emission factors for stationary combustion of various fuels, including biomass. See here: 

http://www.ecfr.gov/cgi-bin/text-idx?SID=834bf8d737d2100f8affa21bc7b13bbc&node=40:22.0.1.1.3.3.1.10.18&rgn=div9

10 Please see section VIII of the preamble for more information on biomass in the context of this rulemaking.
9

2012 Rate (lbs/MWh)

2012 mass 

(lbs) 2012 Generation (MWh) 2012 Capacity

Starting Covered 

Fossil Rate 

(lbs/MWh)

A B C D E F G H I J

Coal Rate

OG Steam 

Rate NGCC Rate

Other 

Emissions Coal Gen

OG Steam 

Gen NGCC Gen Other Gen NGCC MW

Ohio 2,126 1,332 963 284,732,506 86,473,075 321,602 20,907,183 214,178 4,343 1,897

Note, when the values in the above cells shaded green and blue are applied to the equation below, the state’s 2012 “unadjusted fossil” emission 

rate (or historical fossil rate) for likely covered sources equals 1,897 lb/MWh. 

Historical fossil emission rate = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

 Coal gen. + OG gen. + NGCC gen. + “Other” gen.

Step 2: BSER Block One - Calculation of state fossil emission rate goal for covered sources resulting from heat rate improvement (HRI)

After this historical data is collected for each state, the EPA begins to adjust particular variables to the data to reflect each building block element 

of BSER. The EPA assumes that a 6% heat rate improvement at the facility will directly translate to a 6% reduction in the net CO2 emission rate. 

Therefore, in conjunction with determining state goals under the Proposed state goal assumptions in this proposal, the EPA adjusts the state-level 

coal emission rate (column A) downwards by 6% to reflect the 6% heat rate improvement. In the case of Ohio, this results in a drop from 2,126

lb/MWh to 1,999 lb/MWh. This completes the building block 1 treatment for the Proposed state goals.

11

 

11 EPA makes a similar adjustment for the Alternative state goals, but uses a 4% HRI improvement assumption when reducing the coal rate
10

Emission Rate (lbs/MWh)

Emissions

(lbs) Generation (MWh)

2012 

Capacity

State Goal 

Post Block 1 

(lbs/MWh)

A B C D E F G H I J

Coal Rate

OG Steam 

Rate NGCC Rate

Other 

Emissions Coal Gen OG Steam Gen NGCC Gen Other Gen

NGCC 

MW

Ohio 1,999 1,332 963 284,732,506 86,473,075 321,602 20,907,183 214,178 4,343 1,795

Note that when the total emission rate is recalculated with heat rate improvement reflected in the adjustment to the state’s coal emission rate, the 

state emission rate drops from 1,897 lb/MWh to 1,795 lbs/MWh. This is not the final state emission rate goal rate, rather an emission rate 

reflecting building block 1 application before moving onto the remaining blocks. The bold areas in the equation below reflect the values that are 

adjusted from their historical level at this step.

State Emission Rate Post Block 1 = (coal gen. x coal emission rate) + (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” Emissions

Coal gen. + OG gen. + NGCC gen. + “Other” gen.

Step 3a: BSER Block Two - Calculation of state fossil emission rate goal resulting from heat rate improvement and redispatch to existing NGCC 

capacity

In the GHG Abatement Measures TSD, the EPA described how historical 2012 data illustrated that a significant number of NGCC plants had a net 

generation that was greater than or equal to its nameplate capacity x 8784 * 0.7 – in other words a 70% or greater capacity factor. It also provided 

analysis supporting a 70% capacity factor as cost-effective and historical data that illustrated the ability to increase utilization at NGCCs under 

favorable market conditions. That portion of the TSD also describes the engineering analysis that suggests the average availability of a NGCC is 

significantly greater than 70%. Building block 2 was intended to reflect the potential redispatch to the state’s existing NGCC fleet up to a 70% 

capacity factor level. 

To operationalize the 70% CF ceiling in the state goal setting, the state’s 2012 existing NGCC nameplate capacity is multiplied by 8,784 hours 

(the number of hours in the 2012 year) and then by 70% to get total potential net NGCC generation at a 70% capacity factor. However, this 70% 

capacity factor represents a redispatch ceiling, and the state’s NGCC generation is only adjusted up to this ceiling if its historic fossil sources 
11

support such a level.12 Therefore, if this ceiling value (MWh) is less than the sum of the state’s 2012 coal, OG steam, and NGCC net generation, 

the historic NGCC generation is increased to this calculated MWh ceiling value representing the NGCC fleet at a 70% capacity factor, and historic 

coal and OG steam generation are ramped down by an equivalent amount of generation. If the generation of existing NGCC at a 70% capacity 

factor is greater than the sum of the state’s 2012 coal, OG steam, and NGCC net generation, the historical NGCC generation is only adjusted to 

equal the total of the 2012 net fossil generation from these sources. In summary, adjusted NGCC net generation is equal to the lesser of existing 

NGCC fleet at 70% capacity factor or 2012 total fossil generation from BSER subjected sources. This preserves the historical total covered fossil 

generation in the state for BSER subjected sources, but reapportions it assuming a 70% state-average capacity factor ceiling for the NGCC fleet. 

The increase in NGCC generation is subtracted from the coal and OG steam generation in proportion to the state’s historic generation. For 

example, if coal historically accounted for 90% of the total coal and OG steam generation in the state, then its historic generation would be 

reduced by 90% of the amount that NGCC generation increases. Likewise, the OG steam generation would be reduced by 10% of the amount by 

which NGCC generation is increased.

Emission Rate (lbs/MWh) Emissions (lbs) Generation (MWh)

2012 

Capacity

State Goal 

Post Block 

2.1 

(lbs/MWh)

A B C D E F G H I J

Coal Rate

OG Steam 

Rate

NGCC 

Rate

Other 

Emissions Coal Gen OG Steam Gen NGCC Gen

Other Gen NGCC 

MW

Ohio 1,999 1,332 963 284,732,506 80,700,563 300,133 26,701,164 214,178 4,342.5 1,739

Note – in the above example, the total covered fossil generation has not increased in the state from the historic totals shown in step 1. It has only 

been reapportioned assuming a 70% capacity factor for NGCC. NGCC generation is adjusted upwards by approximately 6,000,000 MWh, and 

coal and O/G are adjusted downward by the same amount. This increase in NGCC generation reflects the existing fleet increasing from a 

 

12 Fossil sources here refers to those units subject to BSER redispatch building block treatment (i.e., coal, o/g steam, and NGCC)

4,342.5 MW x 8784 hours x 70% CF = 26,701,164
12

historical level of approximately 55% CF up to the ceiling of 70% CF. When these updated generation values are folded into the state goal

calculation, the emission rate drops from 1,795 lb/MWh in Step 2 to 1,739 lb/MWh. The values in bold below reflect the historic data points that 

have been adjusted to reflect building block implementation at this point in the process.1314

State Emission Rate Post Block 2.1 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

Coal gen. + OG gen. + NGCC gen. + “Other” gen.

Step 3b: BSER Block Two, cont. - Calculation of state fossil emission rate goal resulting from heat rate improvement and redispatch to existing 

and under construction NGCC capacity

Step 3a is repeated for under construction NGCC capacity that would also be considered an existing covered fossil source. For this step, “under 

construction” is defined as anything that came online in 2013 or that was under construction, site prep, or testing by January 8, 2014. The EPA 

looked at reported data for 2012 and calculated the average performance of NGCCs that came online in the past 5 years and observed that 55% 

was the average capacity factor for these units.

15 Therefore, the EPA assumed that a 55% capacity factor would be a reasonable representation for 

the expected generation of “under construction” NGCCs capacity under a business as usual scenario. The EPA conservatively designated the 

generation associated with this 55% capacity factor as unavailable for redispatch to reduce CO2 (i.e., not qualifying for building block 2), instead, 

reserving that amount of generation potential to meet other system needs presumed to have motivated the construction of the “under construction” 

NGCCs. Because these sources are nevertheless covered under the state emission rate goal, the emissions and generation from this 55% 

generation are added to the “other” category and averaged into the state goal calculation. The EPA assumes that while these units would operate at 

55% CF under a business as usual scenario, the average availability for these units is greater than 55%, and they too could ramp up to 70% CF 

ceiling, on average, under a BSER framework and displace relatively higher CO2-emitting generation. Thus, 15% of their ultimate CF (70% -

55%) is assumed to be available for redispatch purposes. The MWh associated with this 15% additional CF displaces coal and OG steam 

generation in the same manner as in step 3a. 

 

13 While a 70% capacity factor ceiling is assumed in the state goal setting exercise, the majority of states are not expected to operate their existing fleet at this 

level in EPA’s projected compliance scenarios.

14 In the Alternative state goal calculations, the EPA makes similar adjustments to the historic data but utilizes a 65% capacity factor ceiling in place of the 70% 

CF shown above.

15 http://ampd.epa.gov/ampd/ and available in docket file titled “NGCC capacity factor for units online in last 5 years”.
13

The portion of the “under construction” NGCC unit’s generation that is not considered available for redispatch (i.e., the first 55%) is captured in 

the “other” category. The generation and emissions from these sources are still included in the emission rate quantified as the state goal by 

averaging in their unadjusted emissions and generation. For “under construction” NGCC units that have no 2012 historical data, the generation 

associated with the 55% baseline capacity factor is obtained by using the capacity and historical average emission rate for NGCCs in the state.16 

The emissions total for these units is calculated by multiplying the generation at a 55% CF by the average emission rate for existing NGCCs in the 

state. 

Emission Rate (lbs/MWh) Emissions (lbs) Generation (MWh)

2012 

Capacity

"Under 

Construction" 

NGCC

State Goal 

Post Block 

2.2 

(lbs/MWh)

A B C D E F G H I J K

Coal 

Rate

OG Steam 

Rate

NGCC 

Rate

Other 

Emissions

Coal Gen OG Steam Gen NGCC Gen Other Gen NGCC MW NGCC MW

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343

539

1,715

Note that when the total emission rate is recalculated to reflect the “under construction” NGCC capacity, the state’s emission rate at this step drops 

from 1,739lb/MWh to 1,715 lbs/MWh. This is not the final state emission rate goal rate, rather an interim rate reflecting building blocks one and 

 

16 Note, both Wyoming and Kentucky had “under construction” NGCC capacity, but did not have existing covered NGCC in the state from which a proxy 

emission rate could be derived for the “under construction” capacity. Therefore, the nationwide average NGCC emissions rate of 907 lb/MWh (net basis).

became the assumed emission rate for the “under construction” NGCC in these two states. EPA assumed 800 lb/MWh and 70% capacity factor for the Kemper 

unit as it was not yet operating in 2012. This is reflected in Mississippi’s “Other” Generation and Emissions in step 2. 

http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/4-Thursday/25Aug11-%20Nelson-KemperCapture%20at%20Kemper%20IGCC.pdf and available in the docket file titled “CO2 capture at Kemper”.

4,343 MW x 8784 hours x 70% CF = 26,701,164

539 x 8784 x 15% CF = 710,186

Total NGCC = 27,411,350

539 x 8784 x 55% CF =2,604,017

Total “other”= 2,604,017 + 214,178 = 2,818,195
14

two application before moving onto the remaining blocks. The bold areas in the equation below reflect the values that are adjusted from their 

historical level at this stage. Note the “Other” category is bolded here as it reflects the addition of the 55% utilization of under construction 

NGCC.

State Emission Rate post block 2.2 = (coal gen. x coal emission rate) + (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

 Coal gen. + OG gen. + NGCC gen. + “Other” gen.

Step 4a: BSER Block Three - Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to existing and under 

construction NGCC capacity, and under construction and “at risk” nuclear capacity

In Step 4a, the total under construction nuclear capacity is determined.

17

 Additionally, an amount of the nuclear capacity that is “at risk” of being 

retired is identified as approximately 5.8% of the historical nuclear fleet (see GHG Abatement Measures TSD for further discussion on how the 

percent assumption was derived). This under construction and “at risk” nuclear capacity was incorporated into the state goals as zero emitting 

generation. This was achieved by applying a 90% capacity factor to the nuclear capacity identified as under construction or “at risk” and then 

applying the resulting MWh figure into the denominator of the state goal calculation. Nuclear is not considered a “dispatchable” resource as is 

NGCC capacity. That is, its utilization will remain fairly constant in both a business-as-usual and policy scenario due to both its low variable 

operating cost relative to fossil sources and technical limitations regarding start-up and shut-down times. The differing dispatch economics 

between NGCC and nuclear plants leads to a different treatment in the goal setting. Existing nuclear is not assumed to increase generation in the 

same manner as the NGCC fleet is assumed capable of in the above steps. Instead of redispatching from coal to nuclear in the same fashion as the 

previous steps, the expected generation for new and “at risk” nuclear is simply added to the state goal denominator – resulting in a lower state goal 

emission rate. However, it is important to note that this “under construction and at risk” nuclear capacity is also part of the inventory that the state 

can count towards compliance with its state goal (i.e., zero emitting generation that can be averaged with that of the covered fossil sources in order 

to obtain a rate that is equal to or less than the state emission rate goal). 

 

17 Watts Bar in TN, Vogtle in GA, and Summer in SC
15

Emission Rate (lbs/MWh)

Emissions

(lbs) Generation (MWh)

2012 

Capacity

"Under 

Construction" 

NGCC

Under 

Construction

and “at risk”

Nuclear

State Goal 

Post Block 

3.1 

(lbs/MWh)

A B C D E F G H I J K L

Coal Rate

OG 

Steam 

Rate

NGCC 

Rate

Other 

Emissions Coal Gen

OG Steam 

Gen

NGCC 

Gen Other Gen

NGCC 

MW NGCC MW

MWh

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 993,077 1,699

Ohio has 0 MW of under construction nuclear and 125.617 MW of “at risk” nuclear capacity share as described in the “GHG Abatement Measures 

TSD”(referred to as Nuclear gen uc + ar. This results in an expected nuclear generation amount of 933,077 MWh that is incorporated into the state 

goal calculation (based on 90% capacity factor). When this value is added into the state goal calculation, the state’s emission rate drops from 

1,715 lb/MWh to 1,699 lb/MWh

State Emission Rate Post Block 3.1 = (coal gen. x coal emission rate) + (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen uc + ar.

Step 4b: BSER Block Three, cont. - Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to existing 

and under construction NGCC capacity, new and “at risk” nuclear, and Renewable (RE)

The GHG Abatement Measures TSD describes how the RE generation total for each state was derived from a combination of existing renewable 

generation in the state and target RE levels informed by existing Renewable Portfolio Standards (RPS) in the region. Although the amount of 

assumed RE generation varies by state to reflect the different existing portfolios of renewable resources and the amount of renewable fuels 

available in different regions of the country, the nationwide average assumed under the Proposed state goals is approximately 13% RE by the end 
16

of 2029.

18

 A potential RE generation value is calculated for each state annually for all years between 2020-2029 to reflect the annual growth as 

states move toward a particular regional RE benchmark. The state-specific RE generation values that relate to this goal nationwide average are 

available in the Excel attachment to this TSD and the GHG Abatement Measures TSD. These RE MWh totals include both existing renewable 

resources in the state and new renewable generation.

Emission Rate (lbs/MWh)

Emissions

(lbs) Generation (MWh)

2012 

Capacity

"Under 

Construction

" NGCC

Under 

Construction

and “at risk”

Nuclear

Existing 

and New 

RE

State Goal 

Post Block 

3.2 

(lbs/MWh

)

A B C D E F G H I J K L M

Coal Rate

OG Steam 

Rate

NGC

C Rate

Other 

Emissions Coal Gen

OG Steam 

Gen

NGCC 

Gen Other Gen

NGCC 

MW NGCC MW MWh MWh

Ohi

o 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 

 

2,818,195 4,343 539 993,077 

 

13,775,594 1,512

Ohio had 1,738,622 MWh of RE in 201219 (approximately 1% of total net generation) and would grow to 13,775,594 MWh by 2029 

(approximately 10.6% of current net generation) under the building block three assumptions. This 13,775,594 MWh of RE generation would be 

added into the state goal by adding it in the denominator. The RE value and resulting state goal shown above reflect the 2029 year. When this is 

added into the state goal calculation, the state’s emission rate drops from 1,699 lb/MWh to 1,512 lb/MWh.

State Emission Rate Post Block 3.2 = (coal gen. x coal emission rate) + (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. uc + ar + RE gen.

Step 5: BSER Block 4 - Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to existing NGCC, “under 

construction” NGCC, under construction and at risk nuclear, RE, and demand-side EE

 

18 See “GHG Abatement Measures” TSD available in the docket and on website. Value does not reflect existing hydro generation.

19 http://www.eia.gov/electricity/data/state/ and available in the docket file titled “2012 sales (EIA data)”.
17

A state-specific percent value is determined for each state reflecting the amount of total MWh sales that could potentially be avoided through 

demand-side energy efficiency measures (see GHG Abatement Measures TSD). Annual percentage savings rates for MWh sales are derived for 

each state for all years between 2020 and 2029 in the Proposed state goals. A different set of annual percent savings are derived for 2020-2024 for 

the Alternative state goals. Because of the temporal nature of demand-side energy efficiency, this building block, along with RE portion of 

building block three, are the only BSER components that increase each year. The GHG Abatement Measures TSD explains the rationale and 

derivation of these annual savings rates. Once these state-specific percent savings rates are derived, they are multiplied by the state’s 2012

historical retail sales and scaled by a factor of 1.0751 to obtain an avoided generation value in MWhs.

20

 The 7.51% scaling factor effectively 

converts the retail sales figure into a corresponding total net generation value that accounts for transmission and distribution losses.

21

 The lesser 

of 1) this avoided net generation value, or 2) the avoided net generation value multiplied by the state’s generation share of its sales is then applied 

to the denominator. This last step helps assure that building block four reductions for net importer states are linked to their own in-state 

generation.22 

This step further reduces the state goal. However, the state may also count EE measures towards compliance with its state goal. Therefore, if a 

state achieves the assumed avoided generation based on EE, it does not have to further lower its emission rate from covered fossil-fuel fired 

generators determined in the previous steps. Instead, adding the avoided generation to the denominator (i.e., averaging in the avoided generation 

at a 0 lbs/MWh emission rate) will lower the state’s emission rate used for compliance with the state goal.

 

20 http://www.eia.gov/electricity/data/state/ “Retail Sales of Electricity by State and Sector” and available in the docket file titled “2012 sales (EIA data)”.

21 The 7.51% scaler represents the historical difference between total net generation of electricity (4,036 TWh) and retail sales of electricity (3,754 TWh). 

http://www.eia.gov/electricity/state/pdf/sep2010.pdf and also available in the file titled “State-level Generation – Net Importer and Exporter Derivation for Goal 

Calculation” in the docket.

22 Demand-side energy efficiency measures may result in out-of-state emission reductions for states that consume more electricity than they produce (i.e., net 

importer states). For these net importer states, the proposal’s approach assumes that each MWh of displaced generation from end-use EE would have occurred in 

part inside the state and in in part outside the state. The proportion of generation displaced inside the state is assumed to be equivalent to the ratio of generation 

in the state to consumption in that state. For example, in a state that produces 75% of the level of electricity that the state consumes, this approach assumes that 

each MWh of avoided generation from end-use EE only yields .75 MWh of avoided generation within that state. Only the portion of avoided generation assumed 

to occur within that state is incorporated into the relevant state goal, on the premise that the proposed BSER is intended to quantify emission reduction potential 

at the generators located in the state in question. For more explanation on how these percent values were derived and the underlying data, See “State-level 

Generation – Net Importer and Exporter Derivation for Goal Calculation” in the docket.
18

Emission Rate (lbs/MWh) Emissions (lbs) Generation (MWh)

2012 

Capacity

"Under 

construction" 

NGCC

Under 

Construction

and At risk

Nuclear

Existing 

and New 

RE

Avoided 

Sales via 

demandside EE

Post Block 

4 

(lbs/MWh)

A B C D E F G H I J K L M N

Coal 

Rate

OG 

Steam 

Rate

NGCC 

Rate Other Emissions Coal Gen

OG Steam 

Gen NGCC Gen Other Gen

NGCC 

MW NGCC MW MWh MWh

MWh

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 993,077 

 

13,775,594

 

16,284,584 1,338

As described in the demand-side energy efficiency section of the GHG Abatement Measures TSD, the 2029 percent of generation savings due to 

energy efficiency is calculated to be 11.557% in Ohio23. This value is then multiplied by the retail electricity sales in the state (152,456,864 

MWh)24 and multiplied by 1.0751 to reflect the net generation commensurate with these sales (i.e., inclusive of transmission and distribution 

losses). This results in 18,942,382 MWh of avoided generation. This value is then multiplied by 85.97% (Ohio’s share of sales coming from in 

state power generation) to reflect the amount of avoided in-state generation that results from the energy efficiency investments. This final 

adjustment results in 16,284,584 MWh of avoided generation for Ohio that is assumed for 2029. This avoided generation value is added into the 

denominator and results in the state goal being decreased from 1,512 lbs/MWh to 1,338 lbs/MWh. This concludes the application of all four 

building blocks for the year 2029, and the 1,338 lb/MWh rate reflects Ohio’s adjusted emission rate for the year 2029.

State Emission Rate Post Block 4 = (coal gen. x coal emission rate) + (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. uc + ar + RE gen. + EE gen.

Steps 6 & 7: Interim and Final State Goals

The completion of the previous five steps results in a 2029 emission rate for the state. However, as noted above, the RE and EE assumptions 

change for each year from 2020 through 2029. Thus this procedure is repeated for each of those years using the corresponding RE and EE 

 

23 11.557% reflects rounded value. See Appendix 1 for actual calculated value of 11.55683...% used to arrive at MWh shown above. Most values shown 

throughout this example are rounded for visual purposes. See Appendix for unrounded number. 

24 http://www.eia.gov/electricity/data/state/ and available in the docket file titled “2012 sales (EIA data)”.
19

assumption for that year. This results in a set of annual adjusted emission rates for the years 2020-2029. However, this rulemaking only issues 

two state goals – an interim and final state goal. Thus, goals are derived by averaging, or taken directly from and the annual adjusted emission rate 

values.

For The Proposed state goals:

Interim State Goal – Average of the adjusted yearly emission rates for the period 2020-2029

Final State Goal – The 2029 emission rate (as calculated above) becomes the state goal for 2030 and each year thereafter

For The Alternative state goals:

Interim State Goal – Average of the adjusted yearly rates for the period 2020-2024

Final State Goal – The 2024 emission rate becomes the state goal for 2025 and each year thereafter

The EPA recognizes that the emission rate goals calculated here include measures that may yield reductions in mass emissions but may not yield 

emission rate reductions in practice when observing monitored and reported emission and generation data from affected units. As such, it is not 

fully informative to compare the state goals calculated here to observable emission rates across affected units either historically or in future 

years. For more discussion about how states can demonstrate compliance with these emission rate goals, please see the “State Plans 

Considerations TSD”. For more discussion on emission reductions, please see the Regulatory Impact Analysis.

Finally, the assumptions used to arrive at each state’s goal are not prescriptive of necessary actions that a state must take. As described in the 

preamble, these values are used only for calculating a state goal. A state may choose to comply with that state goal through any combination of 

abatement measures that differ in class and magnitude from those assumed in the state goal calculation.

Example of Final State Goal Calculation for Ohio:

Final Proposed State Goal Rate for Ohio

– ((1,999 x 79,993,008) + (1,332 x 297,502) + (963 x 27,411,350) + 2,791,474,084) = 1,338 lb/MWh

 ((79,993,008 + 297,502 + 27,411,350 + 2,818,195 + 993,077 + 13,775,594 + 16,284,585) 
20

See the accompanying Excel Workbook for all state level data, calculations, and final state level emission rate goals used to calculate the Interim 

and Final State Goals for Options 1 and 2. This workbook shows all the calculations used to transform the historical covered fossil emission rate 

to the Interim and Final State Goal (columns BA and BB) for the Proposed state goals, and (columns AL and AM) for the Alternative state goals.
21

APPENDIX

Appendix 1 - State level goals, underlying state level data, and calculations for The Proposed state 

goals

See “Appendix 1” worksheet in the Excel attachment titled “Appendix 1 & 2 - State Goal 

Data and Computation”

Appendix 2 - State level goals, underlying state level data, and calculations for The Alternative state 

goals

See “Appendix 2” worksheet in the Excel attachment titled “Appendix 1 & 2 - State Goal 

Data and Computation”

*The above referenced workbook has the data and formulas embedded for state goal calculations. 

Therefore, a commenter suggesting an adjustment to a building block assumption or any historic statelevel data can replace the current assumed values with the suggested amount and see the resulting statelevel goal under such assumptions. 
22

Appendix 3 – Summary of state goals under the proposed Existing Source Performance Standard

Proposed State Goals

State

Interim Goal 

(2020-2029)

Final Goal 

(2030 and 

after) State

Interim 

Goal 

(2020-

2029)

Final Goal 

(2030 and 

after)

Alabama 1,147 1,059 Montana 1,882 1,771

Alaska 1,097 1,003 Nebraska 1,596 1,479

Arizona 735 702 Nevada 697 647

Arkansas 968 910

New 

Hampshire 546 486

California 556 537 New Jersey 647 531

Colorado 1,159 1,108 New Mexico 1,107 1,048

Connecticut 597 540 New York 635 549

Delaware 913 841 North Carolina 1,077 992

Florida 794 740 North Dakota 1,817 1,783

Georgia 891 834 Ohio 1,452 1,338

Hawaii 1,378 1,306 Oklahoma 931 895

Idaho 244 228 Oregon 407 372

Illinois 1,366 1,271 Pennsylvania 1,179 1,052

Indiana 1,607 1,531 Rhode Island 822 782

Iowa 1,341 1,301 South Carolina 840 772

Kansas 1,578 1,499 South Dakota 800 741

Kentucky 1,844 1,763 Tennessee 1,254 1,163

Louisiana 948 883 Texas 853 791

Maine 393 378 Utah 1,378 1,322

Maryland 1,347 1,187 Virginia 884 810

Massachusetts 655 576 Washington 264 215

Michigan 1,227 1,161 West Virginia 1,748 1,620

Minnesota 911 873 Wisconsin 1,281 1,203

Mississippi 732 692 Wyoming 1,808 1,714

Missouri 1,621 1,544
23

The Alternative State Goals

State

Interim 

Goal 

(2020-

2024)

Final 

Goal 

(2025 

and 

after) State

Interim 

Goal 

(2020-

2024)

Final 

Goal 

(2025 

and 

after)

Alabama 1,270 1,237 Montana 2,007 1,960

Alaska 1,170 1,131 Nebraska 1,721 1,671

Arizona 779 763 Nevada 734 713

Arkansas 1,083 1,058 New Hampshire 598 557

California 582 571 New Jersey 722 676

Colorado 1,265 1,227 New Mexico 1,214 1,176

Connecticut 651 627 New York 736 697

Delaware 1,007 983 North Carolina 1,199 1,156

Florida 907 884 North Dakota 1,882 1,870

Georgia 997 964 Ohio 1,588 1,545

Hawaii 1,446 1,417 Oklahoma 1,019 986

Idaho 261 254 Oregon 450 420

Illinois 1,501 1,457 Pennsylvania 1,316 1,270

Indiana 1,715 1,683 Rhode Island 855 840

Iowa 1,436 1,417 South Carolina 930 897

Kansas 1,678 1,625 South Dakota 888 861

Kentucky 1,951 1,918 Tennessee 1,363 1,326

Louisiana 1,052 1,025 Texas 957 924

Maine 418 410 Utah 1,478 1,453

Maryland 1,518 1,440 Virginia 1,016 962

Massachusetts 715 683 Washington 312 284

Michigan 1,349 1,319 West Virginia 1,858 1,817

Minnesota 1,018 999 Wisconsin 1,417 1,380

Mississippi 765 743 Wyoming 1,907 1,869

Missouri 1,726 1,694
24

Appendix 4 – Blocks 1 & 2 only State Goals

The table below provides the interim and final goals from just blocks 1 and 2, before the introduction of 

nuclear, renewable, and EE into the denominator. Note – there is no difference between the Interim and 

Final rates through the first two building blocks as the increasing annual potential only applies to block 3 

and block 4.

Proposed State Goals (lbs/MWh) Alternative State Goals (lbs/MWh)

State

Interim Goal

(2020 - 2029 

average)

Final Goal 

(2030 and 

thereafter)

Interim Goal (2020 -

2024 average)

Final Goal (2025 and 

thereafter)

Alabama 1,329 1,329 1,405 1,405

Alaska 1,252 1,252 1,252 1,252

Arizona 900 900 900 900

Arkansas 1,115 1,115 1,196 1,196

California 838 838 838 838

Colorado 1,521 1,521 1,586 1,586

Connecticut 809 809 812 812

Delaware 1,013 1,013 1,068 1,068

Florida 910 910 991 991

Georgia 1,296 1,296 1,375 1,375

Hawaii 1,751 1,751 1,762 1,762

Idaho 858 858 858 858

Illinois 1,865 1,865 1,924 1,924

Indiana 1,834 1,834 1,883 1,883

Iowa 1,846 1,846 1,900 1,900

Kansas 2,186 2,186 2,230 2,230

Kentucky 1,986 1,986 2,031 2,031

Louisiana 1,099 1,099 1,162 1,162

Maine 848 848 848 848

Maryland 1,868 1,868 1,908 1,908

Massachusetts 886 886 886 886

Michigan 1,511 1,511 1,574 1,574

Minnesota 1,369 1,369 1,446 1,446

Mississippi 843 843 843 843

Missouri 1,784 1,784 1,832 1,832

Montana 2,295 2,295 2,343 2,343

Nebraska 1,941 1,941 1,987 1,987

Nevada 882 882 882 882

New Hampshire 878 878 878 878
25

New Jersey 905 905 905 905

New Mexico 1,447 1,447 1,511 1,511

New York 927 927 970 970

North Carolina 1,329 1,329 1,391 1,391

North Dakota 2,226 2,226 2,273 2,273

Ohio 1,714 1,714 1,766 1,766

Oklahoma 1,186 1,186 1,255 1,255

Oregon 852 852 852 852

Pennsylvania 1,480 1,480 1,537 1,537

Rhode Island 918 918 918 918

South Carolina 1,514 1,514 1,576 1,576

South Dakota 1,456 1,456 1,521 1,521

Tennessee 1,798 1,798 1,855 1,855

Texas 1,083 1,083 1,150 1,150

Utah 1,559 1,559 1,614 1,614

Virginia 1,135 1,135 1,216 1,216

Washington 811 811 811 811

West Virginia 1,933 1,933 1,974 1,974

Wisconsin 1,619 1,619 1,689 1,689

Wyoming 2,151 2,151 2,199 2,199
26

Appendix 5 – 2012 Emission Rate and Building Block Application

The table below provides a block-by-block summary for each state and attempts to compare those rates to 

both the state’s 2012 fossil and fossil/RE/Nuclearar emission rate from relevant sources. It summarizes 

the 2012 state emission rates (highlighted in yellow) and the resulting emission rate following the 

application of each successive BSER building block. Column C shows the 2012 emission rate from 

existing sources that could count towards the state goal, including the state goal’s capture of useful 

thermal output at cogeneration units. Column C provides an emission rate that may be helpful to compare 

to the state goal as it covers the same generating source types as those subject to the state goal (with the 

exception of avoided generation via demand-side energy efficiency).

These block-by-block values are purely illustrative and meant to assist in the understanding of the state 

goals. For example, the table illustrates that block 1 & 2 application has no impact on Idaho’s state goal 

relative to its current emission rate as the state does not have any covered coal sources to which a heat 

rate improvement or redispatch assumption is applied. On the other hand, a state like Ohio does see its 

emission rate decrease based on blocks 1 and 2 assumptions.

The state goal development blocks are not prescriptive in terms of abatement measures or magnitude of 

that measure. States have the flexibility to select their own portfolio of abatement measures to comply 

with the state goal. It is also useful to recognize that many states have already moved, or have plans in 

place to move below their 2012 rates provided in columns B and C due to scheduled retirement of certain 

fossil units, new renewable and low emissions generation coming online, State RPS programs, and State 

Energy Efficiency Resource Standards (EERS).

2012 Emission Rate and Building Block Application for Proposed Final State Goal (2030)

A B C D E F G

State

2012 Fossil 

Rate 

(lbs/MWh)

20121 Fossil, 

RE, 

NuclearAR

Block 1 Blocks 1 & 2 Blocks 1, 2, & 

3 

Blocks 1,2,3 

& 4 (i.e.,Final 

State Goal)

Alabama 1,518 1,444 1,385 1,264 1,139 1,059

Alaska 1,368 1,351 1,340 1,237 1,191 1,003

Arizona 1,551 1,453 1,394 843 814 702

Arkansas 1,722 1,634 1,554 1,058 996 910

California 900 698 697 662 615 537

Colorado 1,959 1,714 1,621 1,334 1,222 1,108

Connecticut 844 765 764 733 643 540

Delaware 1,255 1,234 1,211 996 892 841

Florida 1,238 1,199 1,169 882 812 740

Georgia2

1,598 1,500 1,433 1,216 926 834

Hawaii 1,783 1,540 1,512 1,512 1,485 1,306

Idaho 858 339 339 339 291 228
27

Illinois 2,189 1,894 1,784 1,614 1,476 1,271

Indiana 1,991 1,924 1,817 1,772 1,707 1,531

Iowa 2,197 1,552 1,461 1,304 1,472 1,301

Kansas 2,320 1,940 1,828 1,828 1,658 1,499

Kentucky 2,166 2,158 2,028 1,978 1,947 1,763

Louisiana 1,533 1,455 1,404 1,043 978 883

Maine 873 437 437 425 451 378

Maryland 2,029 1,870 1,772 1,722 1,394 1,187

Massachusetts 1,001 925 915 819 661 576

Michigan 1,814 1,690 1,603 1,408 1,339 1,161

Minnesota 2,013 1,470 1,389 999 1,042 873

Mississippi 1,140 1,093 1,071 809 752 692

Missouri 2,010 1,963 1,849 1,742 1,711 1,544

Montana 2,439 2,246 2,114 2,114 1,936 1,771

Nebraska 2,162 2,009 1,889 1,803 1,652 1,479

Nevada 1,091 988 970 799 720 647

New Hampshire 1,119 905 887 710 532 486

New Jersey 1,035 928 916 811 616 531

New Mexico 1,798 1,586 1,513 1,277 1,163 1,048

New York 1,096 978 970 828 652 549

North Carolina 1,772 1,647 1,560 1,248 1,125 992

North Dakota 2,368 1,994 1,875 1,875 1,865 1,783

Ohio 1,897 1,850 1,751 1,673 1,512 1,338

Oklahoma 1,562 1,387 1,334 1,053 964 895

Oregon 1,081 717 701 565 452 372

Pennsylvania 1,627 1,531 1,458 1,393 1,157 1,052

Rhode Island 918 907 907 907 867 782

South Carolina3

1,791 1,587 1,506 1,342 866 772

South Dakota 2,256 1,135 1,067 732 900 741

Tennessee4

2,015 1,903 1,797 1,698 1,322 1,163

Texas 1,420 1,284 1,235 979 861 791

Utah 1,874 1,813 1,713 1,508 1,454 1,322

Virginia 1,438 1,302 1,258 1,047 894 810

Washington 1,379 756 728 444 298 215

West Virginia 2,056 2,019 1,898 1,898 1,687 1,620

Wisconsin 1,988 1,827 1,728 1,487 1,379 1,203

Wyoming 2,331 2,115 1,988 1,957 1,771 1,714

1. “2012 Fossil, RE, NuclearAR” includes all generation subject to the state goals for which data was reported in 2012. That 

data includes generation from covered fossil fuel-fired units (e.g., >25 MW), all RE generation except hydropower, and 
28

approximately 5.8% of nuclear generation (the “at-risk” component of nuclear generation). The 2012 CO2 rates shown 

here have not been adjusted for any incremental end-use energy efficiency improvements that states may make as part 

of their plans to reach these state goals.

2. As described above, Georgia’s state goal includes expected generation from nuclear capacity currently under construction 

at the Vogtle facility. Adding that expected nuclear generation in the “2012 Fossil, RE, NuclearAR” emission rate for 

Georgia would yield a CO2 emission rate of 1,243 lbs/MWh.

3. As described above, South Carolina’s state goal includes expected generation from nuclear capacity currently under 

construction at the Summer facility. Adding that expected nuclear generation in the “2012 Fossil, RE, NuclearAR” emission 

rate for South Carolina would yield a CO2 emission rate of 1,147 lbs/MWh.

4. As described above, Tennessee’s state goal includes expected generation from nuclear capacity currently under 

construction at the Watts Bar facility. Adding that expected nuclear generation in the “2012 Fossil, RE, NuclearAR” 

emission rate for Tennessee would yield a CO2 emission rate of 1,581 lbs/MWh.
29

Appendix 6- Description of State-level Data Development

The unit-level emissions and generation data derived using the eGRID methodology was relied upon for 

determining state-level totals ultimately used in the goal calculation. One notable difference is that 

published editions of eGRID match emissions and generation at the plant level, while the development of 

the state-level data matches emissions and generation at the unit level in order to filter out units that are 

not likely subject to the Rule’s applicability criteria. Also, the state-level data for goal setting were 

limited to the following elements at the unit level: CO2 emissions, nameplate capacity, net generation, 

state location, and information used to place the unit in each category. The data sources are from reports 

from units that submit data to the EPA under 40 CFR Part 75, and Energy Information Administration 

data from forms EIA-860 and EIA-923. The data were assembled at the unit level and were aggregated to 

the state-level generation totals, capacity totals, and emission rates for the following categories: coal 

steam, Oil Gas Steam (O/G steam), Natural Gas Combined Cycle (NGCC) and Simply Cycle Combustion 

Turbines (CTs), and Integrated Gasification Combined Cycle (IGCC). The year 2012 historical values for 

these categories were then modified for each state to derive the state goal emission rates as described in 

the main body of the TSD.

Industrial units that are not grid connected are excluded. Units for which fossil fuel was less than 10% of 

the heat input in year 2012 were also excluded.

For units that report to the EPA under 40 CFR Part 75, reported CO2 emissions were used. These 

emissions are either determined from continuous emissions monitors that measure CO2 concentration and 

stack gas volumetric flow or, for units that combust certain gaseous and liquid fuels, fuel flow meters and 

fuel testing as required under appendix D and E of 40 CFR Part 75. 

For units that do not report to the EPA under 40 CFR Part 75, CO2 emissions are calculated from fuel use 

reported in the EIA-923 and emission factors under EPA’s Inventory of U.S. Greenhouse Gas Emissions

and Sinks or The Climate Registry Default Emission Factors. If no unit level fuel use exists in the EIA923 dataset and prime mover fuel data exists, and there is more than one unit at a plant that has the same 

prime mover (e.g. steam turbine, combustion turbine, etc.), then prime mover fuel level emissions are 

distributed to each generator in the prime mover by proportionately by nameplate capacity. For most 

cases (where all units in the prime mover would likely be covered by the rule), this apportionment does 

not matter because emissions are summed to the state level. However, if there is a smaller unit in the 

prime mover that would not likely be covered by the rule, then this apportionment may not exactly match 

the amount of fuel actually burned and the associated emissions for each unit. Fuels categorized as 

“other” that could not be defined and assigned an emissions factor were excluded from this task.

Net generation is taken from EIA-923 data. If no unit-level net generation exists in the EIA-923 dataset 

and prime mover fuel data exists, and there are more than one unit at a plant that have the same prime 

mover (e.g. steam turbine, combustion turbine, etc.), then prime mover fuel level net generation is 

distributed to each generator in the prime mover proportionally by nameplate capacity. 

Logic for determination of source CATEGORY:
30

CATEGORY Category Name Includes

COALST Coal Steam

Coal is designated as primary fuel. Nameplate capacity 25 

MW or greater or if heat input capacity is 250MMBtu/hr 

or greater

OGST Oil Gas Steam

All steam units not in “Coal Steam” category that have oil 

or gas primary fuel. Nameplate capacity 25 MW or 

greater.

NGCC

Natural Gas Combined Cycle Units -Duct 

burners and heat recovery steam generators 

are included with combustion turbines that 

are 25 MW.

NG is primary fuel or if actual fuel use is >90% NG. 

Combustion turbine parts having nameplate capacity 25 

MW or greater. Any associated duct burners and heat 

recovery steam generators are included.

SST Simple Cycle Combustion Turbines – 25 

MW

Nameplate capacity 25 MW or greater & 33% capacity 

factor & 219,000MWh

IGCC IGCC IGCCs at: Wabash, Polk, Edwardsport
31

Appendix 7 – 2012 Plant-level Data and Unit-level Inventory

See Appendix 7 Excel attachment titled “Appendix 7 – Plant-level data and unit-level 

inventory”. The unit-level data is available in the Docket and titled “2012 Unit-level Data 

Using the eGRID Methodology”.